Marathon Oil Corporation
Q1 2008 Earnings Call Transcript

Published: 1 May 2008

[Operator:]

Good day, and welcome to Marathon Oil’s First Quarter Earnings Conference Call. As a reminder, this call is being recorded. For opening remarks and introductions, I would now turn the call to Mr. Howard Thill, Vice President of Investor Relations and Public Affairs. Please go ahead sir.

[Howard J. Thill:]

Thank you, Jess and I too would like to welcome everyone to Marathon Oil Corporation’s first quarter 2008 earnings webcast and conference call, teleconference. The synchronized slides that accompany this call can be found on our website, marathon.com. On the call today are Clarence Cazalot, President and CEO; Janet Clark, Executive Vice President and CFO; Gary Heminger, Marathon’s Executive Vice President and President of our Refining, Marketing and Transportation Organization; Steve Hinchman, Executive Vice President, Technology and Services; Dave Roberts, Executive Vice President - Upstream; Phil Behrman, Senior Vice President, Worldwide Exploration’ and Garry Peiffer, Senior Vice President of Finance and Commercial Services - Downstream. Slide 2 contains the forward-looking statement and other information related to this presentation. Our remarks and answers to questions will contain forward-looking statements, subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. In accordance with Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10-K for the year ended December 31, 2007 and subsequent forms 8-K, cautionary language identifying important factors, but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements. As most of the numbers we will discuss today are adjusted net income, Slide 3 provides a reconciliation of net income to adjusted net income by quarter for 2006, 2007 and 2008. Turning to Slide 4; adjusted net income for the first quarter 2008 was $767 million, an increase of about 8.5% compared to the first quarter of 2007 and 53% compared to the fourth quarter 2007. Slide 5, compares these same quarters on a per share basis, and shows adjusted net income was up approximately 5% from the year-ago first quarter and about 53% above the fourth quarter of 2007. During the first quarter, we had approximately $717 million weighted average fully diluted shares outstanding, and we repurchased approximately $2.8 million shares during the quarter. Moving to Slide 6, the year-over-year increase in adjusted net income was largely a result of price and volume growth in our Upstream segment; and the increase in our Integrated Gas segment income due to our Equatorial Guinea LNG facility, which started operations during the second quarter of last year, mostly offset by our lower refining and wholesale marketing gross margin and higher exploration expense. As shown on Slide 7, the increase in adjusted net income for the first quarter of 2008, compared to the fourth quarter 2007 was a result of higher upstream liquid hydrocarbon and natural gas realizations, higher upstream sales volumes, lower exploration expense, and higher contributions from the oil sands, mining and integrated gas segments, both of which were slowed by maintenance activities in the fourth quarter of 2007. These positive effects were partially offset by a lower refining and wholesale marketing gross margin. Turning to Slide 8, Upstream segment income for the first quarter was up $219 million over the fourth quarter, 2007 reflecting higher realization and sales volumes, and lower exploration costs and income taxes partially offset by higher DD&A expense. As shown on Slide 9, upstream sales volumes were higher in the first quarter of 2008, as compared to both the first and fourth quarters of 2007, mainly as a result of the full uninterrupted quarter of natural gas sales to our LNG plant in Equatorial Guinea. First quarter 2008 income also benefited from higher average realizations, which increased $1.71 per barrel of oil equivalent or BOE over the fourth quarter of 2007. Moving to Slide 10, domestic upstream income increased $91 million from the fourth quarter, largely a result of higher realization and sales volumes and lower exploration expense. This was partially offset by higher income taxes and DD&A, and lower other revenue, mainly as a result of lower natural gas purchase and resale activities. Turning to Slide 11, improved differentials for Gulf Coast sour and Wyoming asphaltic grades and higher Gulf Coast sweet and spot WTI premiums, all contributed to our significant price realization improvement relative to the WTI benchmark. Our lower 48 natural gas realizations were higher than the increase in bid week pricing largely as a result of stronger basis differentials for natural gas sold in the Mid-Continent and Rockies. Turning to slide 12, first quarter domestic upstream expense excluding exploration expense was $2.17 per BOE higher than the fourth quarter primarily as a result of higher DD&A expense and increased production taxes. Domestic upstream income per BOE increased $6.74 quarter-over-quarter reflecting both higher realized prices and higher sales volumes. Moving to slide 13, international upstream income for the first quarter increased $128 million from the fourth quarter to $440 million, this increase was mainly due to a reduction in income taxes, higher realizations and sales volumes and lower production expenses, partially offset by higher exploration expenses related to seismic acquisition in Indonesia and seasonal exploration activity from our in-situ assets in Canada. The large decrease in international taxes was a result of yearend tax accrual adjustments recorded in the fourth quarter. As shown on slide 14, our total international liquids realizations increased less than Dated Brent. While our international crude oil prices actually increased inline with Dated Brent NGO realizations did not keep up with the price accrued. Our international natural gas realizations decreased $0.77 per Mcf due to the increased volumes of the lower priced natural gas sales to the LNG plant in Equatorial Guinea. Turning to slide 15, international upstream income increased $4.81 per BOE primarily due to reduced income taxes as previously discussed higher liquid realization and lower expenses, partially offset by lower gas price realization. I would like to point out that additional value from the Equatorial Guinea gas volumes is realized to LNG facility itself and the sale of these LNG volumes is reflected in our integrated gas segment. Turning to slide 16, Oil Sands Mining Segment income for the first quarter was $27 million compared to a loss of $63 million in the fourth quarter of 2007, when operations were disrupted by a fire at the Scotford upgrader. Net bitumen production before royalties was 24,000 barrels per day for the first quarter less than previous guidance due to weather related issues at the mine and unplanned maintenance at the Scotford upgrader. Segment income for the first quarter includes $36 million after-tax loss on derivative instruments, which were put in place by Western Oil Sands prior to the acquisition, $32 million of which was unrealized. The last of these derivative instruments is set to expire in fourth quarter 2009. Also during the first quarter, the royalty calculation methodology for the Athabasca Oil Sands Project was revised to allow for additional eligible cost on the project. As a result, the 1% royalty rate was retroactively applied to the project as of July 1, 2007. Marathon expects a refund of approximately $32 million were $16 million of that amount realized in the first quarter and the other half as a purchased price adjustment. As shown on slide 17, our total production on a combined basis for the Upstream and Oil Sands Mining Segment was 399,000 BOE per day for the first quarter of 2008, an increase of about 16% from the first quarter of 2007 and about 9% higher than the fourth quarter 2007. Moving to our Downstream business, as noted on slide 18, first quarter 2008 segment loss totaled $75 million, compared to $345 million earned in the same quarter last year. Because of the seasonality the downstream business, I will compare our first quarter results against the same quarter in 2007. The primary factor contributing to downstream change in results quarter-to-quarter was the significant reduction in the Light Louisiana Sweet or LLS, Chicago 6-3-2-1 crack spreads, which averaged only $0.07 per barrel in the first quarter 2008, compared to $5.26 per barrel in the first quarter 2007. On a two-third Chicago and one-third US Gulf Coast basis, the average LLS 6-3-2-1 crack spreads decreased from $5.14 per barrel in the first quarter 2007 to $0.51 per barrel in the first quarter 2008. In addition the company’s per gallon wholesale sales price realizations for non-gasoline and non-distillate products did not increase over the comparable prior-year period as much as the average spot market price for the applicable product in the LLS 6-3-2-1 calculation. For example, the average price of all the products we sell other than gasoline and distillate only increased about $0.55 per gallon, whereas the price of 3% residual fuel increased by $0.73 per gallon on average quarter-to-quarter. Our first quarter downstream results were significantly impacted by planned maintenance activities at our Garyville, Robinson and Detroit refineries. Primarily because of this maintenance activity, our crude oil throughput averaged only 845,000 barrels per day in the quarter, compared to 968,000 barrels per day in the first quarter last year. In addition, manufacturing expenses were about $175 million higher in the first quarter 2008 compared to the same quarter last year, primarily due to the previously mentioned maintenance activities, like product transportation cost and purchased energy cost. The first quarter 2008 segment loss includes a pre-tax derivatives-related loss of about $120 million, compared to a pre-tax derivatives related gain of $26 million in the first quarter of 2007. As Gary Heminger mentioned during our analyst meeting in March, we are transitioning away from the use of derivatives in our P plus pricing strategy. Partially offsetting these negative factors, was an improvement in the spread between gasoline and ethanol prices during the first quarter 2008, compared to the same quarter of 2007. The first quarter 2008 also marks the start up of ethanol production at the 110 million gallon per year Greenville, Ohio plant that is 50% owned by Marathon. As shown on Slide 19, Speedway SuperAmerica or SSA, gasoline and distillate sales were down approximately 8 million gallons in the first quarter 2008, compared to the same quarter in 2007 or a decrease of 1%. SSA same store gasoline sales volumes were down 2.4% and the same store merchandise sales were down 0.7% in the first quarter 2008 compared to the same quarter in 2007. SSA’s gross margin for gasoline and distillates was about $0.115 per gallon in the first quarter of 2008, compared to about $0.122 per gallon in the same quarter of 2007. Slide 20 provides a summary of segment data, along with reconciliation to net income. Slide 21 provides select preliminary balance sheet and cash flow data. Cash adjusted debt-to-total capital at the end of the first quarter was approximately 24%. As a reminder, the cash adjusted debt balance includes just under $500 million of debt service by US Steel. Year-to-date, preliminary cash flow from operations was approximately $800 million and preliminary cash flow from operations before working capital changes was approximately $1.3 billion. Slide 22 provides guidance for the second quarter and full year 2008. Production available for sale excluding oil sands mining is forecast to be between 355,000 barrels and 370,000 barrels of oil equivalent per day versus 375,000 barrels of oil equivalent per day available for sale in the first quarter of 2008. The decrease is largely a result of seasonally lower gas sales in the North Sea and Alaska, combined with scheduled down time at our Equatorial Guinea LNG facility. I will now the turn the call over to Clarence Cazalot, Marathon President and CEO.

[Clarence P. Cazalot Jr.:]

Thank you, Howard. As we’ve reported, our Upstream segments recorded sales volume in the first quarter of 2008 was 378,000 barrels of oil equivalent per day. I think it’s important to note that this represents a growth of 11.5% above the first quarter of 2007 and a 6.6% above the fourth quarter of 2007. This growth is mainly attributable to our gas sales in the LNG plant in EG. For 2008, we are on track to deliver the production guidance discussed with you at our recent meeting in New York, our 380,000 barrels to 420,000 barrels of oil equivalent per day despite the delays we had seen in our Alvheim and the outside operated Neptune projects. At Alvheim we had experienced about a 10 day weather delay in moving offshore, but commissioning of the FPSO is nearly complete and we expect first production to occur over the next two to three weeks. Production from the Vilje field is anticipated during the latter half of the second quarter and peak production of 75,000 net barrels of oil equivalent per day from these two fields is expected by early 2009. At Neptune the operator, BHP advises the repair design is ongoing and they expect to provide additional guidance on timing, of completing repairs in the coming weeks. The operator has suggested that first production may occur in the third quarter. At this point I’ll turn it back to Howard for questions.

[Howard J. Thill:]

Thank you, Clarence. Justine we will now open up the call to questions. I’d like to remind everyone, for the benefit of all listeners to please identify yourself and your affiliation. Question and Answer

[Operator:]

[Operator Instructions]. And the first question comes from Doug Terreson with Morgan Stanley.

[Doug Terreson:]

Good afternoon guys. In refining, our refinery throughput and product sales were lower in rest of the year-ago period, when Howard was talking about this. You mentioned that plan and unplanned maintenance and I guess indirectly slower demand explained part of the decline. And so, my question regards, whether addling of capacity was relevant to and also whether or not you have any capacity just idled today as well. And just any color you could provide on that decline would be appreciated?

[Gary R. Heminger:]

Yeah, Dough, this is Gary.

[Doug Terreson:]

Hi, Gary.

[Gary R. Heminger:]

You absolutely right, in Howard’s presentation, the majority was due to planned maintenance and some unplanned maintenance in the first quarter, very little was due to idled throughputs. However, through the quarter and today there are some areas within the country that, you don’t keep your reformers completely full…what’s makes your gasoline portion of your outputs. So, I’d say, was being out of right now or just in some regions part of the reformer side of the business.

[Doug Terreson:]

Okay. And just to clarify, I think Howard also mentioned that the cost and refining were higher by $175 million versus the year ago period and that was really explained by maintenance and purchase energy cost. And so, obviously some of that will be recovering, some of it won’t. But do you have an expectation, just to how much you can reduce that number by going forward?

[Gary R. Heminger:]

Well, here Doug we have completed a little bit lets when over into April as we finished up the Robinson turnover.

[Doug Terreson:]

Okay.

[Gary R. Heminger:]

But the majority of this expenditure was in the first quarter was all planned. Howard said earlier a little bit of unplanned. Going forward, we don’t have anything significant planned at this time over the next couple of quarters and some turnaround activity will startup in the fourth quarter. And Gary has a number here that he’ll share with you as well.

[Garry L. Peiffer:]

Yeah, Doug, this is Garry Peiffer. Part of that a little over $100 million of that was planned maintenance and activities associated with that. So, we are experiencing higher cost in the refineries. So, we wouldn’t expect an extra 60 or 70 million every quarter, but that’s probably right neighborhood.

[Doug Terreson:]

Okay. That’s great thanks a lot.

[Operator:]

And next question comes from Neil McMahon with Sanford Bernstein.

[Neil McMahon:]

Hi, guys. I have two questions. Firstly, just maybe turning back to Angola, there has been a lot of movement in stocks over the last few months associated with exploration discoveries yet. It’s one of the areas that has been strange for you guys is basically looking at the combined volumes discovered in block 30, 31 and 32. Any update to the Analyst Day Presentation that it looks from my calculations that, the gross volumes discovered in those blocks are somewhere between 2.5 to 3 billion barrels recoverable somewhere in that order of magnitude. So, rather this is the first question.

[Philip G. Behrman:]

Yeah, Neil, this is Phil Behrman. The only update that we can give you is what we have said in the earnings release. We have announced the Portia discovery in block 31 and then we also noted that we have three additional wells that have reached total depth. We can’t obviously talk about those which blocks those are on and those include exploration and appraisal wells. So, some were add new volume, and some will confirm some of the existing volume and we have already been discovered by the initial exploration well. And in addition to that, we have two rigs currently drilling in Angola. As we have told you before it’s were lowest to get out in front of the operators, who provide information and we are providing as much information as we can without violating any of our contracts in Angola.

[Neil McMahon:]

Phil, maybe just a follow-up there, have you signed in it, as per the geological community, but strange so much attention has been put on Brazil. Yet nobody has done an addition of all those discoveries in offshore Angola. Because it seems like people have just become immune to any incremental discoveries there.

[Philip G. Behrman:]

I guess it’s hard for me to answer, what other individuals are saying about exploration areas. What I will tell you is, that the addition of discoveries, of course were not things that we recorded at the analyst meeting and so those will add individual volumes. The impact will be as we begin to commercialize all of these successes and of course as we have told you with that process starts in 2008, and then we are queuing up these “development areas” in Block 31 and Block 32 and I think sequentially over time you will see these discoveries commercialized.

[Neil McMahon:]

And maybe just a final question for Clarence and Gary. Given the way refining been over the last six months and now you are starting to very much hook in the oil sands part of your portfolio. Might we see any refinery divestments maybe some of those refineries that are not as hooked in to the system as maybe Detroit or Garyville are. Might you see slimming down of the refining side of the business as you start expanding the E&P side of the company?

[Clarence P. Cazalot Jr.:]

Neil, this is Clarence. We are not in a position to talk about individual assets, but I’d simply reiterate, what Janet said at the analyst meeting, which is we are undertaking a portfolio review of all of our assets. So that portfolio review isn’t simply with respect to their financial performance currently projected, but also the strategic fit, we see of those assets in our portfolio for the long-term and recognizing that we as a company and there is a management team regarded by creating and delivering value for our shareholders. You’ll have to accept that as we look at this, we’ll take those actions that make the most sense for the company. But I’m not prepared to address any specific refinery or any other outside at this time.

[Neil McMahon:]

Okay, great, thanks.

[Operator:]

And the next question come from Doug Leggate with Citi.

[Doug Leggate:]

I’m fine, good afternoon everybody. The intuitive gas business looks like had a pretty decent contribution this quarter. Can you help us get a little bit of an idea what the split was between the LNG facility and the balance, because it looks like you capture under the contract you have with BG [ph] may have been in a little better given the environment and perhaps your guidance suggested the past and I have got one follow-up.

[David E. Roberts Jr.:]

Doug it’s Dave Roberts. I guess I’d point you to a number of things, obviously because of our commitments to BG we can’t discuss what the nature of the S curve looks like, but I would remind everybody that we are FOB sellers at the facility. We had previously pointed out a single point on the curve that should give you a relative guidance point that is a $6 Henry Hub, we have an FOB net of 345 to Marathon. And the other thing I would point you to is, we did 24 cargos last year, 15 in the first quarter of this year and hopefully with that bit of information you can start to triangulate around why the segment was so much more profitable for us in the quarter.

[Doug Leggate:]

Okay, great. And then the follow-up is on tax. In your corporate line, you always have this corporate tax adjustment and in this quarter that seems of taken you down to the low end of your guidance range on tax. Is there anything specific to Q1 that has caused that and should we be looking towards the lower end of the guidance range or maybe just give us some color on how we should think about that going forward?

[Janet F. Clark:]

Sure Doug this is Janet. That corporate lines they always tend to bounce around particularly in the first quarter because, of course, we’re on till 18 [ph] where we try to tell what our effective tax rate will be for the full year. And so as the mix changes during the year, you’re going to see that corporate adjustment adjust. However, in the first quarter there were a couple of items that I’ll call your attention to. We did get a $49 million tax benefit related to the deferred tax liability that we had in Canada. And, if you looked at the 10-K, you’d see that when you booked that acquisition, it was about US$1.5 million. You also remember that because the Canadians lowered their federal tax rates, we had a special item about $200 million benefit. So you can imagine that starting here we were about $1.3 billion US. So, as the Canadian weakened during the first quarter, we got a reduction to that liability and therefore a benefit. That was the biggest item that caused - mixed changes expected throughout the year.

[Doug Leggate:]

Okay. Just one final one from you if I can, this is on Oil Sands this time. You mentioned in your prepared remarks, Howard that you were starting - drawing top exploration activity on the in-situ. Can you maybe just elaborate around that a little bit in terms of what we should expect, because clearly those bookable reserves and to know something I don’t think it was fractured really too much in to the acquisition of Western when you did other time [ph]?

[David E. Roberts Jr.:]

Doug this is Dave Roberts. I would say that we indeed did factor in some of the value for in-situ because obviously we wouldn’t have gotten that for free. But what the activity related to the amount that we expended was 63 wells drilled on our Elk [ph] river properties that we have the 20% interest in and Chevron’s the operator. And some associated seismic spend and 21 wells drilled in the 100% owned Marathon Birchwood property. The analysis of those well results and the course taken is ongoing, and it will lead to potential decisions in the future, not in the near term about how those properties maybe developed.

[Doug Leggate:]

Okay. That’s great. Thank you.

[Operator:]

And moving onto Paul Sankey with Deutsche Bank

[Paul Sankey:]

Hi, good afternoon. The buyback level is known to be lower in Q1, is that a new ratable level that we should think about or is that kind of on it’s way to zero, as we go through the rest of the year. Thanks.

[Janet F. Clark:]

Paul, it’s Janet. Yes, as we said at the analyst meeting in March, we are continuing to do the share buyback program albeit at a modest level. Not necessarily expected to stay at that rate if we could accelerate it or we could slow it down. We still have the expectations that by the end of 2009, we should be able to complete the balance of the authorization that was out there. But that’s one of the beauties of the stock buyback program is you do have that flexibility to either accelerate it or slow it down depending upon what your opportunities are.

[Paul Sankey:]

Thanks, Janet. And Gary if I could an update on your major CapEx projects as they are going on in the downstream. Could you just give us the very latest on Garyville and Detroit. Thanks.

[Gary R. Heminger:]

Sure. At Garyville we are approximately 47% complete right now on time, on budget, and we have the majority of the engineering complete, Paul and we are at heavy end of the construction phase. So that is going very well. In Detroit we - just yesterday was the another public hearing on the permit and we should hear within the next couple of weeks on the stage of the air permit, which will be required for construction. So, we will continue to move forward on our engineering on that project.

[Paul Sankey:]

Thanks, Gary and if I could just leave you with an open question and that will be it from me. You did make an interesting observation at the analyst meeting, that you expected very low levels of utilization to persist in the US refining. That’s proved to be a very solid prediction. Is that still your view of how will go through the summer? Secondly any observations you had on demand, you have given some same-store sales numbers here that looks bit scary, if you could just add any color around that; that would be terrific. And finally any interesting observations you had on ethanol and I will leave it there. Thank you.

[Gary R. Heminger:]

Okay. First of all on utilization, as we expected turnarounds, Paul in the first quarter, we expected it went to be higher and as we go into the second quarter, I will say the turnarounds, where we see them will slim down significantly. And it’s all going to depend on the spreads and its mainly the utilization I think its going to be driven by the spreads of the bottom of the barrel. If you can get asphalt and reset prices to for the margins to equate much closer to the cost accrued you will see the utilization go up, but I would say where we stand right now, where we would expect utilization to continue to struggle and be at the lower end. As far as same-store sales the numbers that was in Howard’s speech, as we go through April, we are seeing about a, still a 2% decline in year-to-date, but about 1% to 1.3% for the month of April decline in same-store gasoline sales. Now say on the distillate side, looking at our total market on distillate, we are seeing a slowdown and very traffic of across the country closer to a 4% to 5% slowdown part of that is going on rail, but I think just a slowing down of the economy. Lastly, on ethanol, as ethanol and corn prices are moved around and there were ethanol despite vis-à-vis gasoline, those continues to be a strong blending component and ethanol year-to-date in the pass of wheat market and it looks like ethanol is up about a 120,000 barrels per day were same period of last year. So, as to say it continues to be a strong blending components and it continued to see it’s growing in the lower part of head one.

[Paul Sankey:]

Thank you.

[Operator:]

Moving on to Robert Kessler with Simmons & Company.

[Robert Kessler:]

Good afternoon. I have got more of a strategic angle to the utilization question that just looking simply your total throughputs albeit that they are down quarter-on-quarter and year-on-year, you still got over a $1 million barrels a day running through your refineries. And then you just look one line down in your slide at the Chicago, 6-3-2-1 crack running at mere $0.07 a barrel. I mean it just sort of begs a question, why not throttle back even further. And I’m sure that there is some complexities in terms of contractual commitments and the like I’m just turning refineries on and off any given quarter, but maybe just if you could address the conceptual idea of not, why not pulling back further?

[Gary R. Heminger:]

That’s a very third question, Robert and we look at that everyday the crudes we are buying, what the market prices are and especially in Chicago, what the most out differentials are and you are correct when you can’t hurdle the north-south differential either we had enough inventory within path two to be able to supply your customers or if you can transport it up to the pipelines, and probably the transportation cost would make sense to refine it in the Gulf Coast. So, we do look at those numbers everyday and making our determination of the right way or more sufficient and optimal way to run the refineries. And going back to the Doug Terreson’s question, as far as anything shut in, you always look at that last barrel that’s going in the refinery. Your base utilization going through your process units, pretty well, we line out your refineries. But usually the last 5% or so of the barrel that’s you really have to be careful all then and believe me, we look at those everyday very carefully.

[Robert Kessler:]

Fair enough. Thanks Gary.

[Operator:]

Next question is from Erik Mielke with Merrill Lynch.

[Erik Mielke:]

Good afternoon. Thanks for taking my question. My question is relate to the production for 2008 and your guidance where you got 380 to 420. What would take you to the low end of the guidance range and what would take you to the upper end of that range? And as part of that question, could you also address your expectation for Equatorial Guinea for Q3 and Q4 given how strong it was in the first quarter and the maintenance you highlighted for the second quarter?

[David E. Roberts Jr.:]

Yeah, Erik, this is Dave Roberts. I guess, without speculating too much on how you could reach either end of the range, is obviously the lower end could be reached in the event that we had unforeseen difficulties with bringing on two major projects on this year, which is Clarence highlighted. We certainly don’t expect giving our growing dated confidence that our time is within weeks that coming on stream. In terms of upside, again it will be reliability and performance of those two projects, because there are significant opportunities in all time of that how quickly we get the projects to ramp up, but we will see. We have taken a reasonable engineering approach for how we think the fields will come on line. With respect to the facilities in Equatorial Guinea; as Howard mentioned we will take a 15 day shutdown in the second quarter which will impact our volumes in the quarter. Basically, that will be the first turnaround at the facility. We will be able to do some de-bottlenecking there. So we would expect Q3 and Q4 to be at least as strong into the first quarter, and we will see if we can potentially upgrade the throughput of that facility to give us some additional volumes as well.

[Erik Mielke:]

Okay, that was very clear. Thanks. I have a follow up question on, maybe for Janet on dividends. You announced your dividend for the second quarter yesterday or for the first quarter to be paid in the second quarter and you’ve got it slant. Is that what we should expect for the rest of the year, given your earlier comments on buybacks as well?

[Janet F. Clark:]

Yes. We look at the dividend every quarter and make that decision on a quarterly basis. We don’t get ahead of time. So I am not going to speak for the rest of the year. But at the analyst meeting we talked about the fact that we recognized dividend as an important component of total shareholder returns. And in fact one of the charts that I showed there had modest dividend increases embedded in it on an annual basis. So it’s not a promise but it’s something that we look at and seriously consider.

[Erik Mielke:]

Great. Thank you.

[Operator:]

And this question will come from Paul Cheng with Lehman Brothers.

[Paul Cheng:]

Hi guys. Number of hopefully quick questions. Gary, when we are looking at in the second quarter, how much of your crude purchase is still going to the p+1 [ph]?

[Gary R. Heminger:]

Paul in the second quarter as we mentioned, Howard had in his speech and as I talked there in March in New York. We have started to decrease our use of derivatives and to mitigate crude oil price risk. And I really don’t want to get in to, as we are switching over, I really want to go in to the exact percentage as you can understand for competitive reasons as you are out trying to buy crude oil. But in the second quarter we have started that, and as we look going forward we do not believe this change will affect our income significantly.

[Paul Cheng:]

Okay, so we’ll assume that in the second quarter we are not going to see much of the divesting on those already.

[Gary R. Heminger:]

I would say a minor portion in the second quarter, because we didn’t start completely on April 1, but we have made a significant debt in that derivative activity.

[Garry L. Peiffer:]

And Paul this is Garry Peiffer. When you start in April that’s really for May business. So or if you start in March that, you got the pump month, you already dealing with all these also. So it’s not always as clean as you might expect it to be.

[Paul Cheng:]

Sure, fully ended and that’s why I asked that I mean how much do we assume or expect it?

[Gary R. Heminger:]

Right, there will be a little bit of transition. March was really -you are purchasing May. You know some April, some May depending on how you are buying it. But it will transition out in the first couple of months.

[Paul Cheng:]

Sure. Since I got you two gentlemen. Maybe I can ask two other question along the downstream in [inaudible]. Gary when I am looking at your operating stack, talking about in the first quarter refining and supplied margin, there is a negative $0.24 [ph] per gallon. In the fourth quarter there’s a $0.048 of profit. And if we look at the sales volume and we do the math, I mean sequentially from the fourth to the first quarter, your operating profit dropped - in supply and refining by about $280 million or about $170 million after-tax. So I’m quite surprised and touchingly suffice to say that you only lost $75 million in the quarter. But I have some difficulty that, why you only lose $75 million where is the other $75 million loss associated with the refining and supply margin was that where we’ll pick up the benefit?

[Gary R. Heminger:]

Okay, Paul. As Howard mentioned and as we try to mention in the earnings release we are a seasonal business not only from a standpoint of our sales but also kind of the expenses to go along with that, so we always compare and we always talk about light quarters not sequential quarters. So when we were given our interim update or interim guidance or update as well as in the remarks here that Howard just gave, we cannot compare everything quarter-to-quarter. Now if you do it sequentially like you do it, we tend to get a different mix of variances obviously. And primarily the biggest effects that we get when we go from the fourth quarter of ‘07 which is a calendar year end to where first quarter is, we don’t have as many expenses typically in the first quarter, non-manufactured expenses in the first quarter as we do in the fourth quarter. We had less transportation cost, we saw less. We have less - some of our incentive compensation accruals that we are truing up in the fourth quarter. As you might recall, we did have very good year last year. So as we true those up, we don’t have the same outlook this year. So you get a totally different mix of expenses quarter sequential to quarter.

[Paul Cheng:]

And Gary that took you to the tune of 100 million pre-tax?

[Gary R. Heminger:]

It’s big number. That’s right. So I guess when you look at us and probably most of the refineries I think its best to kind of look at, what are those deltas calendar quarter to calendar quarter not sequentially?

[Paul Cheng:]

Okay. In Oil Sand, Gary, when I looking at you report $27 million in profit, you have $36 million in divested loss, but you also gained $16 million in the royalty refund. So, that means, that on a twin basis that there is a $47 million after-tax, but that seems to suggest that entire operating cost at above $67 per barrel that seems to high. Are we doing something wrong in this calculation?

[Gary R. Heminger:]

Well, I don’t have that type what we detailed here, Paul. Let me try to work on reconciliation to get it back to Howard to get you.

[Paul Cheng:]

Okay, that’s great. Janet different subject, do you have effective tax rate by division for the year and also the second quarter?

[Janet F. Clark:]

I think, we’ve just given guidance for the full year, effective tax rate.

[Paul Cheng:]

You gave guidance for the full year, for the full corporation, but do you have it divided by divisions?

[Janet F. Clark:]

I don’t think we’ve given guidance on that, Howy thoughts?

[Howard J. Thill:]

Not. We do not have that today, Paul.

[Paul Cheng:]

Okay.

[Howard J. Thill:]

We have that internally, obviously, but we have not provided that externally.

[Paul Cheng:]

Is it possible that you guys can share that number?

[Howard J. Thill:]

We will discuss it and get back with you, Paul.

[Paul Cheng:]

That would be great. And for David, [Inaudible] Norway, when you finally come on stream, what is the unique detail there in cash operating cost, should we assume?

[David E. Roberts Jr.:]

Paul, I have to get back to you on that as well. I don’t think we’ve given that level of detail for single asset.

[Howard J. Thill:]

No, we do not give that kind of detail on single asset, Paul.

[Paul Cheng:]

Yeah, it because assumed that I mean given we have some delay and cost over run the DD&A could be pretty high.

[Gary R. Heminger:]

Paul, we did give the F&D cost on the full Alvheim/Vilje project at the analyst meeting and we would not expect any significant changes from that.

[Paul Cheng:]

I see. Okay, very good. Okay, thank you.

[Operator:]

[Operator Instructions]. Next question come from Mark Gilman with Benchmark.

[Mark Gilman:]

Folks, good afternoon. What percentage of that derivative loss that $120 odd million was not offset by physical market effects in the first quarter.

[Garry L. Peiffer:]

Mark, its Garry Peiffer. I don’t have that number. We don’t really track it that way, so we believe that there all offset in some fashion and shipped that happen in the same quarter because we mark-to-market everything. We don’t try to use hedge accounting on our derivative activity. So, it’s all off set may just not be in the same quarter.

[Mark Gilman:]

But within the quarter Gary, give me a ballpark, is it 10% or 80%.

[Garry L. Peiffer:]

I don’t know. I’d be truly guessing.

[Mark Gilman:]

Okay.

[Garry L. Peiffer:]

What I can tell you though is of that $120 million, about $81 million was due to managing price risks that’s going to how we buy our crude oil. The other $45 million, $46 million was due to inventory, where we had excess inventories that we build up, that we were hedging the price on and rest of it was kind of a miscellaneous breakdown between other category. So, most of it was driven by making price risk and as if you know the structure changed to the point in the first quarter with ‘08, where we were a negative $0.41 on structure versus like $1.25 last year contain yourself. So some of that effect is structured just happening and the rest of it, is just the fact there was a price increase of about $6 or $7 from the end of the year to the end of the first quarter.

[Mark Gilman:]

Okay. Given the royalty situation in Alberta and the change in cost allocation for the purposes, when do you expect payout to be achieved now based on whatever price assumption you want to utilize to answer the question?

[Clarence P. Cazalot Jr.:]

What is that, go ahead.

[Howard J. Thill:]

That’s something we let the operator speak to or that’s not something we would get ahead of that on.

[Mark Gilman:]

Okay. Let me try another one. I think you said that the all time deal was now going to take in early 2009. Was my understanding that you pre-drilled the development wells there and if that’s accurate why so longer ramp?

[David E. Roberts Jr.:]

Mark, this is Dave Roberts. That’s a fair question and what we did say it by early 2009 it goes back to my earlier statement about we have taken…I have gotten in trouble for using this word before. We taken a very prudent course in terms of how we think that various fields and wells are going to ramp up over the course of year and that’s the reason we are using that language. We do, we have a number of wells drilled and ready to go and we have them sequenced throughout the remainder of the second and third quarter, how they are going to be joined to the production facility and a lot of that depends on how those wells perform, when they are put on and making sure that we manage the reservoirs properly and so it will be an engineering decision as we bring the wells on line.

[Mark Gilman:]

Okay. Going on to Phil Behrman if I could, on the Stones appraisal well, Phil can you talk at all about the pay interval you encountered and what the location was relative to discovery?

[Philip G. Behrman:]

Yea, Mark, we can’t talk about lot of things in excess. Let me give you a little bit of context for it. We had a lot of operational problems and lot of the data we would like to have collected, we weren’t able to because of these operational problems. That been said, we were further up dip from the original hole we were probably in the range of about 400 seats further up dip towards the crest of the feature. And as I mentioned we encountered sands, hydrocarbon filled in the lower tertiary. Obviously all the hydrocarbons are oil and that’s about the limit at what we can say. We are still meeting with our partners because the data is still coming in on the well. And as we get consensus of the partnership on all the interpretations of what we’ve encountered from this data, I think we can be a little more forthcoming. But we are hampered at this point because we are still getting the data.

[Mark Gilman:]

Okay. One of the production - the question if I could. Will you produce liquids in EG during the time that the LNG facility shutdown.

[Garry L. Peiffer:]

Yes. The gas has actually turned back to the field market. It doesn’t slowdown the gas production. It just goes back to recycling like we did before the LNG facility came on stream.

[Mark Gilman:]

Okay, so the liquids won’t be impacted, it’s merely the gas which we are injecting sort of selling. Okay. Guys thanks very much.

[Howard J. Thill:]

Well with that we’d like to thank everyone for joining our conference call and have a good afternoon.

[Operator:]

That does conclude today’s conference. We do thank you for your participation.